Method and apparatus for compressing rich natural gas

ABSTRACT

A method and apparatus for compressing rich natural gas is described. The apparatus has a compression stage that has a gas inlet for receiving rich natural gas. The compression stage includes one or more compressors and one or more cooling elements. A pressure vessel is also included for receiving the compressed gas from the compression stage and a liquid outlet is connected between the compression stage and a vessel having a pressure that is less than the pressure in the compression stage. The vessel has a gas outlet connected to the gas inlet. The method includes the steps of subjecting a stream of rich natural gas to a compression cycle to form a compressed gas and a condensate, separating the condensate from the compressed gas, flashing at least a portion of the condensate to a gas and recycling the flashed condensate into the compression cycle.

FIELD

This relates to a method and apparatus for compressing rich natural gas.

BACKGROUND

A hydrocarbon well being produced for its crude oil will often produce natural gas and water with the crude oil. This “solution” or “associated” natural gas is usually referred to as “rich,” meaning it is composed of methane along with heavier hydrocarbons. The composition of the natural gas and the amount of gas relative to the liquid varies between wells. If the well is not connected to a gathering system, the natural gas is often simply vented or flared.

SUMMARY

There is provided a method of compressing rich natural gas. A stream of rich natural gas is subjected to a compression cycle to form a compressed gas and a condensate. The compression cycle may include more than one compression stage and more than one cooling stage and the rich natural gas may be compressed and cooled to a pressure and temperature that is outside the phase envelope of the compressed gas. The condensate is separated from the compressed gas and at least a portion of the condensate is flashed back to a gas. The flashed condensate is then recycled back into the compression cycle.

There is further provided a method of compressing rich natural gas, the phase of the rich natural gas being defined by a phase diagram having a phase envelope. The method comprises the steps of: defining a path on the phase diagram from an uncompressed state to a compressed state, at least a portion of the path being within the phase envelope of the phase diagram; manipulating the rich natural gas along the path to form a compressed gas and a condensate; removing the condensate from the rich natural gas and flashing at least a portion of the condensate to a gas; and reintroducing the flashed condensate into the path.

There is further provided an apparatus for compressing rich natural gas that includes a compression stage that has a gas inlet for receiving natural gas. The compression stage has one or more compressors and one or more cooling elements. A pressure vessel is included for receiving the compressed gas from the compression stage. A liquid outlet is connected between the compression stage and a vessel having a pressure that is less than the pressure in the compression stage. The vessel has a gas outlet connected to the gas inlet of the compression stage. The vessel is used to recycle gas back into the compression stage to capture additional rich natural gas.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features will become more apparent from the following description in which reference is made to the appended drawings, the drawings are for the purpose of illustration only and are not intended to be in any way limiting, wherein:

FIG. 1 is a schematic view of a well site.

FIG. 2 is a schematic view of a loading and unloading process.

FIG. 3 is a schematic view of a multi-element gas container.

FIG. 4 is a graph showing a phase diagram of a typical rich gas.

FIG. 5 is a graph showing a compression path of a rich gas.

DETAILED DESCRIPTION

The various components of molecules are often referred to by the number of carbon atoms they contain. For example, rich natural gas may be composed of methane (C1), ethane (C2), propane (C3), butane (C4), and heavier hydrocarbons (generally referred to as C5+ herein).

When natural gas is produced from an oil well that is not connected to a gathering system, the gas must be disposed of in some way. Often, this is done by flaring or venting. It would be preferable to capture the rich natural gas in order to store and process the rich natural gas, such as by transporting the gas to a central processing location. In order to store the gas in a container in an economically viable manner, it must be stored at a higher density, which is generally achieved by compression and cooling. The state diagram of a rich natural gas is shown in FIG. 4. The rich natural gas is in a densified state in a particular temperature and pressure range. The presence of heavier hydrocarbons (or other additives) allows a denser phase to be reached than would be possible with, for example, methane alone. U.S. Pat. No. 7,137,260 (Perry) entitled “Method and Substance for Refrigerated Natural Gas Transport” describes the effect of additives, temperature and pressure on the density of natural gas mixtures. The difficulty is that the different components tend to separate in different phases during compression and cooling, as each component has a different transition point.

The present discussion relates to a method and apparatus that permits the rich natural gas to be captured and stored in a single densified or compressed state, such that it may then be stored or transported, as the case may be.

Referring now to FIG. 1, there is shown an example of a well site 10 that may be the source of rich natural gas. There are shown three wellheads 12 that each produce water, liquid hydrocarbons, and rich natural gas. The well site also has a three-phase separator 14 and a treater 16. Three-phase separator 14 and treater 16 are used to help separate the produced fluids into the various components, with water being stored in water tank 18, oil being stored in oil tank 20, and natural gas being diverted to the flare stack 22. The stored fluids are then periodically removed from tanks 18 and 20 through truck loading points 21. It will be appreciated that other well sites may vary from what is depicted. For example, some well sites may produce from fewer or more wellheads 12. In addition, the separation equipment may be different, for example, there may only be a single production tank, with the phase separation occurring within. As these processes are well known and the actual well site design will depend on the preferences of the operator and the characteristics of the well. What is important to note is that the discussion related to capturing the rich natural gas applies to each of these well sites, where rich natural gas is produced through the wellhead.

As depicted, the gas phase from treater 16 is traditionally flared by a flare stack 22. However, in the preferred embodiment, the gas phase is captured through line 24, and injected into a compressor 26, as shown in FIG. 2. Compressor 26 works in conjunction with a dryer 28 to remove moisture in the rich natural gas. A suitable dryer may be obtained from Xebec of Montreal, Canada. Compressor 26 is used to compress and cool rich natural gas captured from well site 10 with the goal of obtaining a single densified state that is enhanced by the presence of heavier hydrocarbons. A possible path across through the phase diagram is shown in FIG. 5. Gas at about 20 PSI and 60° F. is input into compressor 26. The gas is then compressed to about 150 PSI. As the compression will cause the temperature to rise to about 210° F., the gas is then cooled to about 100° F. The cooling element in this example uses ambient air to cool the gas. This allows the compressed gas to be cooled to no more than ambient temperature. The present example assumes that the compressed gas temperature will be cooled to around 10 to 20° F. of ambient summer temperatures, estimated at 80 to 90° F. During other seasons, it may be possible to cool the gas further, or it may be necessary to use a refrigeration unit and a coolant to achieve the necessary temperatures. During the second and third stages of compression, the gas may exit the phase envelope, but is cooled into the phase envelope 25. The path is defined by the behavior of a modeled gas that is first compressed, then cooled. The actual path may have more or fewer cycles, and may have different intermediate pressures and temperatures, depending on the composition of the gas, the requirements of the equipment and the preferences of the user. As is apparent, heavier hydrocarbons will fall out during the compression and cooling cycle, the majority of which will occur during the cooling process. Along the depicted path, these condensates will typically be composed of C3 and heavier hydrocarbons, although there may be some C2 as well. As a single dense phase is desired, the condensates are removed from compressor 26. However, heavier hydrocarbons help achieve a single dense phase, and also have economic value. Accordingly, some or all of the condensates are recycled to a point before the compressor 26. As depicted on FIG. 1, the condensates are injected at a point indicated by arrow 30, upstream of treater 16. Because treater 16 is at a lower pressure, at least a portion of the condensates are flashed. Some of the heavier hydrocarbons, primarily C5+, may not be flashed simply by reducing the pressure. These heavier hydrocarbons may be encouraged to flash, such as by heating, or exposing them to even lower pressure. They may also be deposited into oil tank 20 for delivery with the other liquid hydrocarbons. As these heavier hydrocarbons are valuable, it may be desirable to encourage the C5+ condensates not to flash. On many well sites, a treater 16 will not be available. In these circumstances, a different low pressure tank may be used, such as the production tank itself, where any liquids that do not flash are immediately deposited with the other liquid hydrocarbons.

Referring again to FIG. 5, compressor 26, illustrated in FIG. 2, may achieve the desired final pressure and temperature using a three-stage compression and cooling approach. The final temperature and pressure is preferably outside the phase envelope 25, which ensures that the hydrocarbon mixture will remain as a gas as during storage or transportation. Once the gas is stored in a pressure vessel, only the temperature may be changed by external conditions. Preferably, the location of the gas on the phase diagram is such that any increase or decrease in temperature will not cause the gas to re-enter the phase envelope 25, which could cause condensates to form. The box 29 on the phase diagram represents a preferred operating range, based on the composition of the gas. The operating range is preferably outside the phase envelope, and preferably maximizes the densifying effect, but still have reasonable pressures and temperatures. Operating outside the envelope may be necessary in order to ensure liquid does not fall out of the gas during transport, as transporting two phases is against regulations in some jurisdictions. The optimal range will be determined in each situation, such as for each well. The gas composition is preferably monitored to make any necessary adjustments.

In another example, the target temperature may be well below ambient temperature, which results in a lower pressure and higher densification. For example, the target temperature may be as low as 0 to −40° F. The final temperature and pressure will be selected based on the composition of the gas being compressed and its phase envelope, and will be selected based on the cost of additional cooling and compression and the benefit of additional compression and densification. For example, richer gases (gas with a larger component of heavier hydrocarbons) reach a densified state at a higher temperature than leaner gases. Accordingly, it may be sufficient to use a cooler that uses ambient air as described in the example above, which is less expensive to run than a refrigeration unit, which would be necessary to achieve colder temperatures. In addition, it is less economically viable to cool smaller volumes.

It will be understood that the phase envelope 25 of the compressed rich natural gas will not necessarily be the same as the phase envelope 25 defined by the original rich natural gas. As heavier hydrocarbons fall out, particularly if they are not all recycled back to compressor 26, the phase envelope 25 will shift toward that represented by dotted line 27. Dotted line 27 is merely an example, as the actual phase envelope 25 will depend on the composition of the gas.

It has been found that this recycling process does not create a build-up of C3 and C4 hydrocarbons at the inlet of compressor 26. It is suspected that one reason for this is that the path chosen does not cause all C3+ hydrocarbons to fall out, based on the limited range in which the compression and cooling stages occurs.

Referring again to FIG. 2, once suitably compressed by compressor 26, the gas is loaded into a pressure vessel 32, such as may be carried by a transport truck, via a loading station 34. Pressure vessel 32 may be, for example, a multi-element gas container, also called a “tube trailer.” These types of vessels generally have a capacity of between 150 L to 3000 L (water volume), but other volumes may be designed for if desired. While the description above refers to the gas being compressed to its final pressure and temperature, this is not done from the beginning. Instead, the output of compressor 26 is substantially the same as the pressure of pressure vessel 32. By “substantially the same,” it will be understood that the pressures are in the same range in order to avoid significant pressure drop. However, some pressure differential is necessary in order to have the pressurized gas flow into pressure vessel 32, and to account for the increase in pressure that will occur as the gas is loaded. Referring to FIG. 3, pressure vessel 32 includes a dip tube 33 that extends to the bottom of vessel 32. By opening a valve connected to dip tube 33, the pressure in pressure vessel 32 will force any liquid out of dip tube 33. Accordingly, it is preferred to have pressure vessel 32 at a slight angle, such that the liquids accumulate at dip tube 33.

Referring to FIG. 2, once pressure vessel 32 is filled, it is transported to an unloading station 35 and offloaded. Unloading station 35 may be located at a processing plant, an access point to a natural gas pipeline or at the end user directly. A pressure reducing station 36 may be used to obtain a low pressure output as is known in the art.

In one example, the pipeline at unloading station 35 may have a pressure of 250-300 PSI, resulting in an “empty” pressure of 350-400 PSI for pressure vessel 32. The pressure in pressure vessel 32 after unloading will vary depending on the pressure at unloading station 35. Some compressors 26 may be limited in their minimum output to, for example, 600 PSI. Accordingly, the compressed gas will experience a pressure drop as it is loaded into pressure vessel 32, which may result in condensates forming. This may be avoided by only emptying pressure vessel 32 to match the minimum pressure that can be achieved by compressor 26, or using a compressor with a lower minimum output. However, another solution is to remove any condensates via dip tube 33, illustrated in FIG. 3, until the pressure in pressure vessel 32 is matched to the output of compressor 26. The condensates may be recycled as described above. Once the minimum pressure output of compressor 26 is substantially the same as pressure vessel 32, the output pressure follows the pressure increase in pressure vessel 32 as progresses toward the target temperature and pressure. Referring to the phase diagram in FIG. 5, this means that compressor 26, illustrated in FIG. 2, will only pass through the first two stages of the path initially and only partially through the third stage until toward the end of the filling process. Referring to FIG. 2, it is preferred that any cooling occur in compressor 26 as this is more likely to result in condensates forming, and liquids are not desirable, and in some cases not permitted by regulation, in pressure vessel 32. However, as described above, it is possible to remove condensates from pressure vessel 32 if necessary during loading. While the path followed by compressor 26 involves changes in both pressure and temperature, the path in pressure vessel 32 will preferably minimize any temperature changes to also minimize the formation of condensates, which generally occur as the result of a temperature or pressure drop.

Referring again to FIG. 3, pressure vessel 32 is preferably a tube trailer made up of multiple tubes 38 that can be loaded and unloaded through valves 40 at either or both ends. This is particularly useful in unloading, as it can accelerate the unloading process. During unloading, a pressure drop is occurring, such that condensates are likely to fall out of the compressed gas. In order to prevent a slug of liquid, it is preferred that the liquid be removed continuously from pressure vessel 32, which involves removing liquid through dip tube 33. Generally speaking, the amount of liquid falling out of the gas will be the limiting factor in the ratio of gas removed from either end of tubes 38 in order to ensure the liquid is continuously removed.

In this patent document, the word “comprising” is used in its non-limiting sense to mean that items following the word are included, but items not specifically mentioned are not excluded. A reference to an element by the indefinite article “a” does not exclude the possibility that more than one of the element is present, unless the context clearly requires that there be one and only one of the elements.

The following claims are to be understood to include what is specifically illustrated and described above, what is conceptually equivalent, and what can be obviously substituted. Those skilled in the art will appreciate that various adaptations and modifications of the described embodiments can be configured without departing from the scope of the claims. The illustrated embodiments have been set forth only as examples and should not be taken as limiting the invention. It is to be understood that, within the scope of the following claims, the invention may be practiced other than as specifically illustrated and described. 

1. A method of compressing rich natural gas, comprising the steps of: subjecting a stream of rich natural gas to a compression cycle to form a compressed gas and a condensate; separating the condensate from the compressed gas; flashing at least a portion of the condensate to a gas; and recycling the flashed condensate into the compression cycle.
 2. The method of claim 1, wherein the compression cycle comprises more than one compression stage and more than one cooling stage.
 3. The method of claim 2, wherein the cooling stage uses ambient air to cool the compressed gas.
 4. The method of claim 2, wherein the cooling stage uses a refrigeration unit to cool the compressed gas below ambient temperatures.
 5. The method of claim 2, wherein the rich natural gas is compressed and cooled to a pressure and temperature that is outside the phase envelope of the compressed gas.
 6. The method of claim 1, wherein at least a portion of the condensate is flashed to a gas by reducing the pressure.
 7. The method of claim 1, further comprising the step of loading the compressed gas into a pressure vessel.
 8. The method of claim 7, wherein the pressure vessel is at substantially the same pressure and substantially the same temperature as the compressed gas.
 9. The method of claim 7, wherein the pressure vessel is at a pressure that is less than the pressure of the compressed gas.
 10. The method of claim 9, wherein the compressed gas forms a condensate when loaded into the pressure vessel, and further comprising the step of removing the condensate from the pressure vessel through a liquid outlet.
 11. The method of claim 10, wherein at least a portion of the condensate from the pressure vessel is flashed to a gas and recycled into the compression cycle.
 12. A method of compressing rich natural gas, the phase of the rich natural gas being defined by a phase diagram having a phase envelope, comprising the steps of: defining a path on the phase diagram from an uncompressed state to a compressed state, at least a portion of the path being within the phase envelope of the phase diagram; manipulating the rich natural gas along the path to form a compressed gas and a condensate; removing the condensate from the rich natural gas and flashing at least a portion of the condensate to a gas; reintroducing the flashed condensate into the path.
 13. The method of claim 12, wherein manipulating the rich natural gas along the path comprises using a compression cycle having more than one compression stage and more than one cooling stage.
 14. The method of claim 13, wherein the cooling stage uses ambient air to cool the compressed gas.
 15. The method of claim 13, wherein the cooling stage uses a refrigeration unit to cool the compressed gas below ambient temperatures.
 16. The method of claim 13, wherein the compressed state is a pressure and temperature that is outside the phase envelope of the compressed gas.
 17. The method of claim 12, wherein at least a portion of the condensate is flashed to a gas by reducing the pressure.
 18. The method of claim 12, further comprising the step of loading the compressed gas into a pressure vessel.
 19. The method of claim 18, wherein the pressure vessel is at substantially the same pressure and substantially the same temperature as the compressed gas.
 20. The method of claim 18, wherein the pressure vessel is at a pressure that is less than the pressure of the compressed gas.
 21. The method of claim 20, wherein the compressed gas forms a condensate when loaded into the pressure vessel, and further comprising the step of removing the condensate from the pressure vessel through a liquid outlet.
 22. The method of claim 21, wherein at least a portion of the condensate from the pressure vessel is flashed to a gas and recycled into the compression cycle.
 23. An apparatus for compressing rich natural gas, comprising: a compression stage having a gas inlet for receiving rich natural gas, the compression stage comprising one or more compressors and one or more cooling elements; a first vessel for receiving the compressed gas from the compression stage; and a liquid outlet connected between the compression stage and a second vessel having a pressure that is less than the pressure in the compression stage, the vessel having a gas outlet connected to the gas inlet of the compression stage.
 24. The apparatus of claim 23, wherein the rich natural gas is compressed and cooled to a pressure and temperature that is outside the phase envelope of the compressed gas.
 25. The apparatus of claim 23, wherein the first vessel is at substantially the same pressure and substantially the same temperature as the compressed gas.
 26. The apparatus of claim 23, wherein the first vessel is at a pressure that is less than the pressure of the compressed gas.
 27. The apparatus of claim 23, wherein the first vessel comprises a liquid outlet for removing condensate from the pressure vessel. 